Method for the gasification of moisture-containing hydrocarbon feedstocks

ABSTRACT

A method for the gasification of a hydrocarbon feedstock that has a high moisture content to produce useful co-products such as high-value hydrocarbon fuels, pure H 2 , electricity, and/or ammonia. The method advantageously gasifies the carbon in the feedstock to carbon monoxide (CO) without producing large quantities of carbon dioxide (CO 2 ). Supplemental hydrogen (H 2 ) is co-produced by reacting steam (H 2 O) generated from the moisture in the hydrocarbon feedstock with a molten metal.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent ApplicationNo. 60/746,748 filed May 8, 2006, which is incorporated herein byreference in its entirety as if set forth in full. This application isalso related to co-pending U.S. patent application Ser. No. 11/746,013filed on May 8, 2007 and entitled “Method for the Gasification ofHydrocarbon Feedstocks”, which is also incorporated herein by referencein its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention is directed to a method for the gasification ofhydrocarbon feedstocks to produce a syngas that is useful for theproduction of hydrogen, hydrogen-containing materials, electricity orother energy products. The method advantageously produces suchhigh-value products, and can reduce the formation of carbon dioxide(CO₂) per unit of energy or commodity produced, as compared to othergasification methods.

2. Description of Related Art

Gasification is a well-known process that converts hydrocarbon materialssuch as coal, petroleum coke, biomass or similar feedstocks into asyngas comprising carbon monoxide (CO) and hydrogen (H₂). Duringgasification, pyrolysis of the hydrocarbon material releases fuel-boundH₂, oxygen, nitrogen and sulfur leaving residual solid carbon char. Someof the carbon char is gasified to CO and H₂ with steam (H₂O), and someof the carbon is gasified to CO with oxygen.

Table 1 is an illustrative list of major hydrogen-containing materials,naturally-occurring materials and man-made materials, arrangedsubstantially according to their H₂ content. TABLE 1 Hydrogen-ContainingHydrogen Relative Phase Material Content (mol.%) Value Gas Hydrogen100.0 High Value Methane 25.1 Ethane 20.1 Propane 18.3 Ammonia 17.8Liquid Jet Fuel 14.1 Gasoline 14.4 Ethanol 13.0 Methanol 12.5 Crude OilLow Value Tar Sands Solid Coal (Eastern US) 4.7 Coal (Western US) 6.2Biomass 5.9 Pet Coke 3.1 Municipal Waste 6.2 Rubber Tires 8.7

One goal of the energy industry is to use methods such as gasificationto convert relatively low-value hydrocarbon materials to clean,high-value liquid or gaseous hydrocarbons that can be effectivelyutilized. Each of the high-value products listed in Table 1 can besynthesized from syngas (H₂ and CO), except ammonia where N₂ replacesthe CO. However, for synthesis to occur the ratio of H₂ to CO in thesyngas (H₂:CO) must approximate the volumetric ratio of the H₂ and CO inthe balanced chemical equation. For example, to make methane (CH₄), thevolumetric ratio of H₂:CO must be about three, because the synthesisequation requires that three moles of H₂ be available for each mole ofCO:3H₂+CO→CH₄+H₂O  (1)

In conventional gasification, some of the carbon is gasified to CO andH₂ with steam (H₂O) in a highly endothermic reaction, and some carbon isgasified to CO with O₂ in a balancing exothermic reaction:C+H₂O→H₂+CO  (2)C+½O₂→CO  (3)

Conventional gasification produces some H₂ from the energy that isreleased as C is oxidized to CO. However, the H₂ produced is only 50vol. % of the total gas released from the splitting of water (Equation2) and that H₂ is diluted to less than 25 vol. % when considering theadditional CO that is produced by the exothermic oxidation of C with O₂that is required for balancing the heat (Equation 3). As a result, thesyngas derived from solid hydrocarbons by conventional gasification hasa H₂:CO ratio that is virtually always less than one, which is too lowto be used for manufacturing the high-value hydrogen-containingmaterials that are needed for commerce.

In order to increase the amount of H₂ derived from conventionalgasification, some of the CO must be used to reduce H₂O and form CO₂ asa by-product via the water gas shift reaction, which is conducted in aseparate reactor after gasification.CO+H₂O→H₂+CO₂  (4)

Thus, when conventional gasification is utilized to produce a high H₂syngas or a substantially pure H₂ gas stream, over three-fourths of theH₂ derives from the conversion of CO to H₂ by the water gas shiftreaction. This step produces large amounts of CO₂, which is commingledwith the H₂ that is subsequently separated, such as with apressure-swing adsorption (PSA) unit. The net driving force forproducing H₂ and associated co-products from solid hydrocarbons is theoxidation of carbon contained within the hydrocarbon to CO₂. Thisoxidation of carbon is stepwise: after pyrolysis isolates H₂ (and othergases such as O₂, N₂ and sulfur) from the carbon, the carbon first ispartially oxidized to CO and the CO is then oxidized to CO₂. Aboutone-third of the heat produced by the complete oxidation of carbon toCO₂ is released in the first oxidation step (C to CO), meaning that theoxidation of the CO to CO₂ via the water gas shift reaction producesabout two-thirds of the total heat released in completely oxidizingcarbon to CO₂.

Accordingly, while H₂ production by coal gasification is an establishedcommercial technology, it is only economically competitive withsteam-methane reformation (SMR) for the production of H₂ when naturalgas is prohibitively expensive. Most gasification of hydrocarbonmaterials such as coal is carried out in moving-bed gasifiers, fluidizedbed gasifiers or entrained flow gasifiers. Among other factors, suchcoal gasification plants have a high capital cost and the gasificationreactors generally have a low availability, about 75 percent, causingdisruptions in the manufacture of syngas. Such a low availability isgenerally unsatisfactory for downstream manufacturing processes thatutilize the syngas (or syngas converted to hydrogen) for oil refining orammonia production.

Several methods for the gasification of hydrocarbon materials have beensuggested that utilize a molten metal to facilitate the reaction. Forexample, Sumitomo Metal Industries has disclosed a method and apparatusfor gasifying hydrocarbon materials utilizing a molten metal reactor. Anexample of this technology is disclosed in U.S. Pat. No. 4,738,688 byNakajima et al. As is disclosed in this patent, hydrocarbon material isgasified by blowing the hydrocarbon material onto the top surface of amolten metal bath with a gasifying agent such as oxygen. In thistop-blowing process, the hydrocarbon material is decomposed at hightemperature points that form above the molten metal. It is disclosedthat the resulting gas is rich in CO and H₂ and in the proportion of CO₂is rather small. The Sumitomo Metal Industries Technology is alsodisclosed, for example, in U.S. Pat. No. 4,389,246 by Okamura et al.,which discloses that a stirring gas can be injected into the bottom ofthe molten metal reactor to increase the efficiency of the process.

Another method using a molten metal reactor was developed by MoltenMetal Technology, as is illustrated in U.S. Pat. No. 5,395,405 by Nagelet al. In this method, organic waste is gasified by injecting the wastethrough the top, bottom or sides of the reactor. Gas can also beinjected through the bottom of the reactor to create a fountain ofmolten metal droplets above the surface of the molten metal. U.S. Pat.No. 5,358,697 by Nagel discloses that the molten metal can include twomolten metal phases, where the second molten metal phase is immisciblein the first molten metal phase. The use of two metal phases enhancesthe oxidation of atomic carbon and forms CO₂, which is discharged to theatmosphere after scrubbing. U.S. Pat. No. 5,537,940 by Nagel et al.discloses a sequential process wherein organics are injected into amolten metal, such that H₂ is formed and removed while carbon dissolvesinto the molten metal. Thereafter, oxygen is injected into the metal tooxidize the carbon and remove carbon oxides. It is disclosed that theformation of CO is favored when the metal is iron.

Another technology using a molten metal reactor, referred to as theHyMelt Technology, has been disclosed by Malone et al. For example, U.S.Pat. No. 6,110,239 by Malone et al. discloses a process in which a highpurity, high pressure H₂-rich gas stream and a high purity, highpressure CO-rich gas stream are produced separately and continuouslyusing a molten metal gasifier containing at least 2 zones, to avoid theneed to separate the gases in downstream equipment. The method caninclude introducing a hydrocarbon feed into a molten metal bath beneaththe molten metal surface in a feed zone operating at a pressure above 5atmospheres and decomposing the hydrocarbon feed into H₂, which leavesthe feed zone as a H₂-rich gas, and into carbon, which dissolves in themolten metal. The carbon concentration in the metal is controlled to beat or below the limit of solubility of carbon in the molten metal. Aportion of the molten metal is transferred from the feed zone to anothermolten metal oxidation zone operating at a pressure above 5 atmospheresinto which an O₂-containing material is introduced beneath the moltenmetal surface to react with a portion of the carbon to form a CO-richgas. In this manner, the carbon concentration in the molten metal iscontrolled so it does not reach the concentration at which theequilibrium oxygen concentration would exceed its solubility limit inthe molten metal.

Other methods of carbon gasification using a molten metal bath includethat disclosed in U.S. Pat. No. 4,496,369 by Torneman, which discloses amethod and apparatus for the gasification of carbon by the injection ofcarbon, O₂ gas and iron oxides beneath the surface of a molten ironmetal bath.

Steam reduction is another known method for the manufacture of H₂ gas.The steam reduction method utilizes the oxidation of a metal (Me) tostrip oxygen from steam, thereby forming hydrogen gas. This reaction isillustrated by Equation 5.xMe+yH₂O Me_(x)O_(y) +yH₂  (5)

To complete the cycle in a two-step steam reduction process, the metaloxide must be reduced back to the metal using a reductant such as carbonor CO. For example, CO has an oxygen affinity that is similar to theoxygen affinity of H₂ and they are equal at about 812° C. Attemperatures above about 812° C., CO has a greater affinity for oxygenthan does H₂, and the CO or carbon will reduce the oxide of Equation 5back to the metal as indicated by Equations 6 and 7.Me_(x)O_(y) +yCO→xMe+yCO₂  (6)Me_(x)O_(y) +yC→xMe+yCO  (7)

Generally stated, the function of the metal/metal oxide couple is totransfer oxygen from the steam to the reducing gas (CO) without allowingthe H₂O/H₂ of the hydrogen production step to contact the CO/CO₂ of themetal oxide reduction step. Neither the metal nor the metal oxide isconsumed by the overall process.

Oxygen partial pressure (pO₂) relates to the facility with which themetal may be oxidized (e.g., by steam) and the oxide may be reduced(e.g., by CO). A related mathematical expression is pH₂O/pH₂, which isproportional to the oxygen partial pressure. Also, an equivalent andinversely related quantity is the hydrogen fraction, expressed as:$\begin{matrix}\frac{{pH}_{2}}{\left( {{pH}_{2} + {{pH}_{2}O}} \right)} & (8)\end{matrix}$

Certain metals react strongly with water, releasing hydrogen. The oxygenpartial pressure in equilibrium with these metals and their oxidestogether is extremely low. Once the oxides are formed, they cannot beeffectively reduced back to the metal. Conversely, there is anothergroup of metals that produce insignificant quantities of hydrogen whenreacted with water. The oxygen partial pressure in equilibrium withthese metals and their oxides together is quite high. The oxides,therefore, can be easily reduced by CO or carbon.

Between the two foregoing groups of metals are other metalscharacterized by an oxygen affinity that is roughly the same as theoxygen affinity of H₂. Included in this intermediate group of metalsare, for example: germanium (Ge), iron (Fe), zinc (Zn), tungsten (W),molybdenum (Mo), indium (In), tin (Sn), cobalt (Co) and antimony (Sb).These are elements that readily produce H₂ from H₂O wherein theresulting oxide can be reduced by carbon and/or CO. That is, thesemetals have an oxygen affinity such that their equilibrium pH₂O/pH₂ islow enough to be practical for the production of hydrogen, yet the metaloxide is readily reduced by carbon at normal pyrometallurgicaltemperatures (e.g., about 1200° C.). These metals are referred to hereinas reactive metals, meaning that the metal can be oxidized by steam andthe metal oxide can be effectively reduced by carbon or CO.

Iron is a useful reactive metal, and the steam reduction/iron oxidationprocess was the primary industrial method for manufacturing hydrogenduring the 19th and early 20th centuries. At elevated temperatures, ironstrips oxygen from water, leaving pure hydrogen.Fe+H₂O→FeO+H₂  (9)

Excess water is required to maximize H₂ production from a given amountof iron. After the H₂ is produced, excess water is condensed leaving anuncontaminated hydrogen gas steam.

An example of this method is disclosed in U.S. Pat. No. 6,663,681 byKindig et al. In this method, steam is contacted with a molten metalmixture including a first reactive metal such as iron dissolved in adiluent metal such as tin. The reactive metal is oxidized to its metaloxide, forming a hydrogen gas; thereafter, the metal oxide can bereduced back to the metal for further production of hydrogen withoutsubstantial movement of the metal or metal oxide to a second reactor.

An extension of this work is reported in U.S. Pat. No. 6,685,754 byKindig et al. This patent discloses a method for the production of ahydrogen-containing gas composition, such as a synthesis gas includingH₂ and CO. It is disclosed that the molar ratio of H₂:CO in thesynthesis gas can be well-controlled to yield a ratio that is adequatefor the synthesis of useful products such as methane or methanol. Inthis method, a molten metal is provided and steam is contacted with themolten metal to react the first portion of the steam with the metal toform hydrogen gas and a metal oxide. The hydrocarbon material is alsocontacted with the melt in the presence of the steam to react thehydrocarbon material with a second portion of the steam to form CO. Agas stream is extracted from the reactor, where the gas stream can havea molar H₂:CO ratio of at least about 1:1. After a period of time, thesteam contacting can be terminated and the metal oxide can be contactedwith a reductant to reduce the metal oxide back to the molten metal.

SUMMARY OF THE INVENTION

The present invention is directed to a highly stable, highly efficientprocess for the gasification of a wide range of hydrocarbon feedstocks.As used herein, a hydrocarbon feedstock is any material that comprisescarbon and hydrogen, even where the hydrogen is present in relativelylow amounts, such as in pet coke. The process can advantageouslyminimize the production of carbon dioxide (CO₂) for the production of agiven quantity of chemical product and net energy export.

The method of the present invention can advantageously be carried outcontinuously in a single reactor for the uninterrupted production of asyngas.

It is also an advantage of the present invention that the solid orliquid hydrocarbons used as the feedstock can be low-value, contaminatedhydrocarbons. The method can also have a lower capital cost thanconventional gasification.

The syngas stream that can be produced according to the presentinvention advantageously has a higher CO:CO₂ ratio than the syngasstream from conventional gasification. For conventional gasification, aminimum ratio of CO:CO₂ must be established to extract H₂ from water.Gasification according to the present invention involves oxidation ofthe metal (iron) as represented by Equation 5 and reduction of thejust-formed oxide by carbon as illustrated by Equation 6. Addition ofEquations 5 and 6 eliminates the metal and metal oxide and leaves justcarbon to reduce the water, the same reaction as for conventionalgasification. Therefore, based upon a superficial comparison, the sameCO:CO₂ ratio should be required in both cases.

However, to create the metallic iron, a source of hydrogen in thepresent invention, FeO must yield its oxygen to carbon. Because the FeOis in ionic solution with other oxides comprising a slag and because thecations of the other oxides in the slag also exert a binding force onthe oxygen, additional energy is required to extricate the oxygen fromthe mixture of FeO and other oxides. The additional energy required toextricate the oxygen from the solution of mixed oxides arises fromcombusting additional carbon to increase the ratio of CO:CO₂.

Syngas with a high ratio of CO:CO₂ contains more energy than syngas witha low ratio of CO:CO₂. Therefore, more useful work can be obtained froma given amount of high CO:CO₂ syngas per unit of CO₂ produced than froma syngas with a lower CO:CO₂ ratio. This is a significant advantage ofthe present invention.

The syngas stream, after heat recovery and purification, is comprised ofCO and H₂ in a molecular ratio generally reflecting the C:H ratio in thehydrocarbon feedstock that is being reacted, and the CO content isgreater than the H₂ content. The method of the present invention canalso co-produce electricity, nitrogen, sulfur and pozzolanic slag alongwith the syngas stream. The value of these salable co-products cansubstantially or completely off-set the cost of H₂ production.

The syngas stream and co-produced electricity can be merged in variousways that utilize substantially all of the energy contained therein forsubsequent conversion into H₂ or H₂-containing commodities and/oradditional electricity and/or steam. By way of example, the commoditiescan be selected to include: pure hydrogen; pure hydrogen and electricityand/or steam; ammonia, electricity and/or steam; methane, electricityand/or steam; liquid fuels such as gasoline, diesel and jet fuel,electricity and/or steam; or solely electricity and/or steam. Steam isuseful as a source of process heat required by many industries.

More specifically, the syngas stream, N₂, electricity and otherco-products can be produced by processing a hydrocarbon feedstock, waterand air through the following equipment:

-   -   (1) a molten metal reactor producing a hot crude syngas stream;    -   (2) a gas-purifying train that is designed to recover a purified        syngas and heat from the hot crude syngas stream, while        rejecting particulate material, water-soluble halogens and        sulfurous compounds, and optionally rejecting or recovering H₂,        to form a refined syngas stream;    -   (3) a steam generator (boiler);    -   (4) an air separation plant to produce substantially pure O₂ and        N₂ from air;    -   (5) equipment for sulfide roasting, such as a fluidized bed;    -   (6) equipment for processing sulfur, such as a Claus plant;    -   (7) equipment for generating electricity;    -   (8) heat recovery equipment, such as where steam is the medium        for heat recovery; and    -   (9) gas-compression and other general support equipment.

The energy that is available in the syngas stream can be used inconjunction with one or more of the following chemical conversionprocesses:

-   -   1. catalyzed gas-synthesis loops operating at relatively low        temperatures and high pressure;    -   2. the Fischer-Tropsch process, including modifications thereof;    -   3. electrical generation, such as by gas-turbine combined cycle;    -   4. the electrolysis of water; and/or    -   5. the water gas shift reaction for producing additional pure        H₂, followed by separation of CO₂.        These chemical conversion processes can be used to produce, for        example:    -   1. Pure hydrogen, such as by combining H₂ from gasification with        H₂ produced either by the electrolysis of water or by water gas        shift of some of the CO otherwise dedicated to electricity        production;    -   2. Pure hydrogen and electricity, where additional hydrogen is        recovered from the syngas stream and CO is rejected back to the        syngas stream for subsequent generation of electricity;    -   3. Ammonia and electricity, where ammonia can be produced in an        ammonia synthesis loop, such as from the syngas stream after        purification to pure hydrogen (or conversion of the small amount        of CO to methane) and N₂;    -   4. Methane and electricity, where methane can be synthesized in        a methanation loop—copious amounts of heat are released by the        methanation reaction, and this heat can be converted into useful        steam;    -   5. Liquid fuels and electricity, where the liquid fuels can be        produced utilizing the Fischer-Tropsch process; or    -   6. Electricity, such as by burning the purified syngas stream in        a combined cycle gas-fired turbine.

Elemental sulfur and pozzolanic slag are by-products of the process andare salable commodities, further decreasing the net operating cost ofthe process.

Accordingly, one embodiment of the present invention is directed to amethod for the gasification of a hydrocarbon feedstock to form a syngas,The method can include the steps of injecting a hydrocarbon feedstockcomprising at least about 10 wt. % H₂O into a molten metal reactor, thereactor containing a molten metal phase comprising a reactive metal anda slag phase, wherein a portion of the H₂O from the feedstock reactswith the reactive metal to reduce the portion of the H₂O to H₂ and forma reactive metal oxide, and wherein a first portion of carbon from thehydrocarbon feedstock reduces reactive metal oxide contained in the slagphase to the molten metal phase. During the injection of the hydrocarbonfeedstock, oxygen is injected into the molten metal reactor to oxidizeat least a second portion of carbon from the hydrocarbon feedstock tocarbon oxides. A syngas comprising H₂ and CO is recovered from thereactor, where the recovered syngas comprises not greater than about 15vol. % CO₂.

According to one aspect of the method, the recovered syngas comprisesnot greater than about 10 vol. % CO₂, such as not greater than about 5vol. % CO₂. The hydrocarbon feedstock can be selected from the groupconsisting of pet coke, coal, municipal waste, rubber tires, wood andbiomass, and the hydrocarbon feedstock can comprise at least about 25wt. % H₂O.

The method can also include the step of injecting a second hydrocarbonfeedstock into the reactor, where the second hydrocarbon feedstockcomprises less H₂O than said first hydrocarbon feedstock.

According to one aspect, the partial pressure ratio of oxidizing gasesto total gases in the reactor as expressed by the fraction:$\frac{\left( {{H_{2}O} + {CO}_{2}} \right)}{\left( {H_{2} + {H_{2}O} + {CO} + {CO}_{2}} \right)}$is determined for the hydrocarbon feedstock by minimizing Gibbs' freeenergy for the reduction reaction employing the hydrocarbon feedstock,and wherein the input rate of a reactant selected from oxygen andhydrocarbon feedstock to the reactor is adjusted to minimize the Gibbs'free energy.

The hydrocarbon feedstock can also comprise sulfur-bearing orchlorine-bearing compounds. Accordingly, the method can include thesteps of recovering sulfur-containing compounds from the syngas,oxidizing the sulfur-containing compounds to form SO₂, contacting theSO₂ with H₂S or H₂, and extracting elemental sulfur from the contactingstep.

When the feedstock comprises chlorine, the method can include the stepsof removing chlorine-containing compounds from the syngas by dissolvingthe chlorine-containing compounds in water and removing thechlorine-containing compounds by water purification.

According to another aspect, the reactive metal comprises iron and therate of injection of the hydrocarbon feedstock is maintained such thatthe iron oxide content in the slag phase does not deviate during theprocess by more than about 5 weight percent. The rate of injection ofthe hydrocarbon feedstock can be maintained such that the iron oxidecontent in the slag phase is at least about 30 wt. % and is not greaterthan about 65 wt. %.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 schematically illustrates the reactants and the resultantproducts that can be produced according to an embodiment of the presentinvention.

FIG. 2 illustrates a binary phase diagram for a tin-iron metal mixturethat is useful in accordance with an embodiment of the presentinvention.

FIG. 3 illustrates a desired temperature operating window that insuresslag fluidity for a FeO/CaO/SiO₂ slag system with a basicity (CaO:SiO₂)of 0.8 according to the present invention.

FIG. 4 illustrates a molten metal reactor that is useful forgasification according to an embodiment of the present invention.

FIG. 5 illustrates a process flow for the continuous production of asyngas according to an embodiment of the present invention.

FIG. 6 illustrates a process flow for the continuous production ofsyngas according to an embodiment of the present invention.

FIG. 7 illustrates an integrated gasification combined cycle (IGCC)power plant.

DESCRIPTION OF THE INVENTION

An overview of the method of the present invention is illustrated inFIG. 1. The method 100 includes providing reactants to a reactor system108, where the reactants include at least air 102 and a moisthydrocarbon feedstock 106 that comprises H₂O in appreciable quantities.

According to the present invention, the hydrocarbon feedstock 106 canadvantageously include relatively low-value hydrocarbons, includingthose having less than about 10 mol. % H₂ and which can also includeimpurities such as sulfur.

More specifically, the hydrocarbon feedstock according to the presentinvention can include low-cost, high heating-value carbon sources suchas petroleum coke, scrap tires and liquid petroleum residues; mediumcost, high heating-value and low-ash, high rank coals that may containhigh levels of sulfur; or low-cost, low-heating value materials such aslow-rank (sub bituminous) coal, biomass and the organic portion ofmunicipal waste products. Plastics contained in municipal waste can alsobe a useful feedstock. Further, wood can also be used as a feedstock.Particularly preferred are petroleum coke, other petroleum residues,scrap tires and high-rank low-ash coal. Petroleum coke (also referred toas pet coke) is a black solid that is obtained mainly by cracking andcarbonizing residues from the distillation of petroleum oils, especiallyheavier petroleum oils (tars). It is an advantage of the presentinvention that the hydrocarbon feedstock can be a low-value hydrocarbonmaterial such as high-sulfur pet coke or low-ash high-rank coal, as thesulfur is readily controlled. Petroleum coke can advantageously havelower ash content than coal and therefore produce less slag.

It is also an advantage of the present invention that the hydrocarbonfeedstock 106 can have a relatively high moisture content to providewater to the reactor system 108 and does not require drying before beinginjected into the molten metal reactor. In this regard, it is preferredthat the hydrocarbon feedstock that is input to the reactor system 108comprise some H₂O. Specifically, the hydrocarbon feedstock 106 cancomprise at least about 10 wt. % H₂O, more preferably at least about 15wt. % H₂O, even more preferably at least about 20 wt. % H₂O and evenmore preferably at least about 25 wt. % H₂O. Although the hydrocarbonfeedstock includes H₂O, the total H₂O should preferably not exceed about50 wt. % of the feedstock and more preferably should not exceed about 40wt. % of the feedstock. It will be appreciated that many hydrocarbonfeedstocks contain such high levels of moisture in their natural state.

A hydrocarbon feedstock having high moisture content can advantageouslylead to the formation of H₂ due to the reduction of the water in thereactor. For example, Powder River Basin (PRB) coal has a relativelyhigh natural moisture content, such as from about 25 wt. % to about 30wt. %. Municipal solid waste and wood can also have similarly highmoisture content. In one preferred embodiment, the hydrocarbon feedstockthat is fed to the reactor has a moisture content such that the moisturecontained in the hydrocarbon feedstock oxidizes the metal atsubstantially the same rate as new metal (Me) is being formed by thereduction of the Me_(x)O_(y) in the slag. It is an advantage that suchhigh moisture feedstocks can be utilized with little or no drying, as istypically required in conventional gasification methods. If the moisturecontent is slightly less than is required to balance the reduction rate,a small amount of additional moisture 104 can be added to the feed, suchas by injecting steam. Conversely, if the moisture content is slightlyhigher than is needed to balance the reduction rate, the addition of adrier hydrocarbon material 105 can reestablish the balance such that theoxidation rate equals reduction rate. Alternatively, the moisturecontent of the moist hydrocarbon feedstock 106 can be partially dried ina steam drier using excess steam created by the process.

The air 102 input to the process provides a source of O₂ and canoptionally provide a source of N₂, which may be needed for theproduction of nitrogen-containing end-products such as ammonia.

The method 100 includes providing for the withdrawal from the reactorsystem 108 of products that can include flue gas 116, electricity 112,elemental sulfur 114, a syngas stream 118, waste water 120 and slag 122.As is discussed in more detail below, the syngas stream canadvantageously have a CO:CO₂ ratio that is higher than knowngasification methods.

Generally, the reactor system 108 generically represented in FIG. 1includes a molten metal bath reactor that contains a molten metal, ormolten metal alloy, and molten slag. A gas train is in gaseouscommunication with the reactor and is adapted to receive and process thecrude syngas stream produced within the reactor. The gas train accordingto the present invention can be adapted to treat the crude syngas streamto recover the sensible heat, to clean and purify the syngas stream ofimpurities such as sulfurous compounds, particulates and mercury, and topreclude the formation of noxious compounds such as dioxins and furans,and form a refined syngas stream. The refined syngas stream canoptionally be burned in a gas turbine with air, such as at a temperaturewhich virtually precludes formation of nitrogen oxides (NO_(x)).Alternatively, the syngas stream can be burned with oxygen at a lowtemperature thereby creating a sequesterable flue gas.

The present invention will now be described in greater detail, and withreference to FIGS. 2-7. According to the present invention, some H₂ isformed by contacting the moist hydrocarbon feedstock with a molten metalmixture that includes at least a first reactive metal such that at leasta portion of the H₂O contained in the feedstock is reduced to H₂ and thereactive metal is oxidized. The reactive metal can be at least partiallydissolved in at least one diluent metal. The diluent metal may also bereactive with the steam, but is, by definition, less reactive with steamthan the reactive metal. Thus, the oxygen from the H₂O in the feedstockpreferentially reacts with the reactive metal to oxidize the reactivemetal to its metal oxide and reduce a portion of the steam to form H₂.

A hydrocarbon feedstock, which includes at least a portion of the H₂O,is injected into the molten metal reactor under conditions of intensemixing, such as by using submerged lances. Under these conditions, themetal oxide is continuously reduced back to the reactive metal by thecarbon derived from the hydrocarbon while at the same time the metal isoxidized back to the oxide with moisture (steam) which originated fromthe moisture accompanying the feedstock. According to one embodiment ofthe present invention, the oxidation rate of the reactive metal, due tomoisture accompanying the hydrocarbon forming steam, equals the rate ofreduction of the iron oxide to iron, e.g., the reduction of the ironoxide by carbon derived from the hydrocarbon. This can be accomplishedby controlling the total amount of moisture going into the reactor, suchas by partially drying the hydrocarbon feedstock or adding somehydrocarbon feedstock with a lower moisture content, or by injectingadditional moisture, such as in the form of steam, to the reactor.

The hydrocarbon feedstock is contacted with a molten metal mixture thatincludes at least a first reactive metal. The reactive metal preferablyhas an oxygen affinity that is similar to the oxygen affinity of H₂ andreacts with the steam to form a metal oxide. For example, the reactivemetal can be selected from germanium (Ge), iron (Fe), zinc (Zn),tungsten (W), molybdenum (Mo), indium (In), tin (Sn), cobalt (Co) andantimony (Sb). The molten metal mixture can include one or more reactivemetals. The reactive metal preferably should: (1) be soluble in thediluent metal(s); (2) have a very low vapor pressure at theoxidation/reduction temperature(s); and (3) produce one or more oxideswhen reacted with steam that also has a very low vapor pressure at theoxidation/reduction temperature(s). A particularly preferred reactivemetal according to the present invention is iron and according to oneembodiment the reactive metal consists essentially of iron.

The reactive metal is preferably at least partially dissolved within asecond metal, or mixture of metals, and the metal into which thereactive metal is dissolved is referred to herein as the diluent metal.The diluent metal may also be reactive with steam, in which case it canbe selected from the group of reactive metals disclosed hereinabove,provided that the diluent metal is less reactive than the reactivemetal. Alternatively, the diluent metal can be selected from the metalswherein the oxygen partial pressure (pO₂) in equilibrium with the metaland oxides together is relatively high. These include nickel (Ni),copper (Cu), ruthenium (Ru), rhodium (Rh), palladium (Pd), silver (Ag),cadmium (Cd), rhenium (Re), osmium (Os), iridium (Ir), platinum (Pt),gold (Au), mercury, (Hg), lead (Pb), bismuth (Bi), selenium (Se) andtellurium (Te). More than one diluent metal can be utilized in themolten metal mixture. The diluent metal should not be a metal whereinthe oxygen partial pressure in equilibrium with the metal and metaloxide together is extremely low.

Preferably, the diluent metal should: (1) combine with the reactivemetal to be liquid in the temperature range of from about 400° C. toabout 1400° C.; (2) have a very low vapor pressure over this temperaturerange; and (3) have the capacity to hold the reactive metal in solution.According to a preferred embodiment of the present invention, thediluent metal is tin and in one embodiment, the diluent metal consistsessentially of tin. However, the molten metal mixture can also includeadditional diluent metals, for example copper and nickel.

A particularly preferred molten metal mixture according to the presentinvention includes iron as the reactive metal and tin as the diluentmetal. Iron has a high solubility in molten tin at elevated temperaturesand the melting temperature of the mixture is substantially lower thanthe melting temperature of pure iron (1538° C.). Although tin is alsoreactive with steam, it is less reactive than iron. For convenience, thefollowing discussion will refer to iron and tin as the reactive anddiluent metals respectively, although the present invention is notlimited thereto.

Due to thermodynamics, H₂O reduction reactions to form H₂ require anexcess of H₂O above the stoichiometric requirement. The total H₂Orequirement (the mass ratio of H₂O required to H₂ produced) for iron ismuch less than for tin at all temperatures and iron will preferentiallyoxidize in the molten metal mixture. As a result, increased levels ofH₂O are utilized with the incoming feedstock, as compared toconventional gasification processes that typically require at leastpartial drying of the feedstock to remove moisture.

One significant advantage of utilizing a reactive metal dissolved in adiluent metal is that the residence time of the H₂O within the reactoris increased with respect to the mass of the reactive metal. That is, agiven mass of iron will occupy a first volume as pure iron, but the samemass of iron will be distributed over about twice the volume if the ironis in a 50 weight percent mixture with a diluent metal such as tin.

It is preferred that the metal mixture be maintained at a temperatureabove the solidus line AC of FIG. 2 (e.g., above 1134° C.), and morepreferably above the liquidus line (I-II-III-IV) of FIG. 2. Ametal-steam reaction temperature that is too high, however, addssignificantly to the operating cost. For the completely molten iron/tinsystem illustrated in FIG. 2, the melt should be maintained at atemperature above the solidus temperature of about 1134° C., morepreferably at a temperature of at least about 1200° C., and even morepreferably at a temperature of at least about 1300° C. For the purposeof reasonable economics, the temperature should not be greater thanabout 1450° C. and more preferably is not greater than about 1400° C. Aparticularly preferred temperature range for the completely moltentin/iron metal mixture is from about 1300° C. to 1400° C. At 1300° C.,about 75 weight percent iron dissolves in tin with sufficient superheatand the mixture stays in the molten state as iron is oxidized. Also, thereaction between H₂O and liquid iron dissolved in tin to form hydrogenat 1300° C. is also quite vigorous and the reaction kinetics areexcellent. Furthermore, the thermodynamics for the H₂O/iron system evenat 1200° C. are relatively good, requiring an excess of only about 12.2tons of H₂O to produce each ton of hydrogen (1.37 moles of H₂O per moleof hydrogen). The preferred operating temperature will also beinfluenced by slag conditions, as is discussed below.

When using a reactive metal such as iron in a diluent metal such as tin,it is preferred that that the metal mixture include at least about 3weight percent iron, more preferably at least about 10 weight percentiron, even more preferably at least about 20 weight percent iron andeven more preferably at least about 40 weight percent iron in the moltenmetal mixture. Further, the amount of iron in the molten metal mixtureshould preferably not exceed about 85 weight percent and more preferablyshould not exceed about 65 weight percent. The balance of the metalmixture in a preferred embodiment consists essentially of tin.Accordingly, the amount of tin in the system is preferably not greaterthan about 97 weight percent, more preferably is not greater than about90 weight percent, even more preferably is not greater than about 80weight percent, and even more preferably is not greater than 60 weightpercent. The molten metal mixture preferably includes at least about 15weight percent tin and more preferably at least about 35 weight percenttin.

A method for reacting H₂O to form hydrogen using an iron-tin mixture isdisclosed in commonly-owned U.S. Pat. Nos. 6,663,681 and 6,685,754, bothby Kindig et al. Each of these U.S. patents is incorporated herein byreference in its entirety.

Thus, H₂O, the bulk of which can originate from the moisture containedin the hydrocarbon feed, is contacted with the molten metal mixture togenerate H₂ and to oxidize the reactive metal to a metal oxide. The H₂Ois contacted with the molten metal mixture in a manner that promotesgood mixing and contact with the molten metal mixture. For example, theH₂O preferably can be contacted with the molten metal mixture byinjection of the hydrocarbon feedstock through submerged lances atvelocities in the lance approaching the velocity of sound. Preferredreactor systems in this regard are discussed below.

Control of the composition of the slag that forms over the molten metalis important to the practice of the present invention. In this regard,the concentration of the iron oxide in the molten slag above the metalcan range from about 30 weight percent FeO to a preferred maximumconcentration of about 65 weight percent FeO, which values are primarilydictated by the temperature of the slag-freeze line. The freeze line forthe slag rises steeply at both high and low concentrations of ironoxide, the points where injection of steam is either initiated orterminated. This is illustrated in FIG. 3. The slag compositionillustrated in FIG. 3 has a basicity (CaO:SiO₂ ratio) of 0.8.

According to the present invention, the optimal slag chemistry (e.g.,the FeO content) can be determined for a selected hydrocarbon feedstock,such that the injection of that feedstock into the reactor maintains asubstantially constant FeO content in the slag.

A slag layer provides a number of advantages, including preventing theiron from exiting the reactor. The temperature in the reactor should besufficient to maintain the slag layer that forms over the metal mixturein the molten state over a range of compositions, as illustrated in FIG.3. Similar to the range of compositions for the molten alloy discussedpreviously with respect to FIG. 2, there is a range of preferred slagcompositions required to ensure adequate slag fluidity and reactivity.FIG. 3 illustrates the preferred operating temperature window (A-B-C-D)superimposed on a graph above the slag freeze line for a FeO/CaO/SiO₂slag as a function of temperature and FeO content. The reactor operatingtemperature must be above the slag freeze line where the slag is molten.Slag properties can be adjusted—for example fluxes such as SiO₂, CaO,MgO, Na₂O, K₂O and mixtures thereof can be added to the reactor toadjust the properties of the slag. Moreover, sulfur and other anions maybe incorporated in the slag to secure satisfactory slag chemistry.

A small amount of CO can also be generated in the gasification reactorfrom the reaction between liquid carbon (dissolved in the melt) and theH₂O that is contacted with the molten metal to form H₂. However, theamount of carbon that can be dissolved in molten iron tends toward zeroas the iron oxide content of the slag increases and therefore the amountof CO generated in this manner is relatively small.

During production of the syngas, the metal oxide that is generated bythe reaction of H₂O can advantageously be trapped by dissolution in theslag layer within the reactor. At the preferred temperatures, the ironoxide is molten and is incorporated into the slag, which is lighter thanthe metal mixture. Therefore, as the dissolved iron is depleted from themolten metal mixture, the molten iron oxide rises through the moltenmetal and contributes to the slag layer on top of the molten metal. Thisalso enables the metal to sink from the slag layer to the molten metalmixture upon reduction of the metal oxide. This accumulation of ironoxide in the slag may require the addition of one or more fluxes tomaintain the slag in the preferred condition with respect to viscosity,reactivity, foaming, and the like.

The gasification method of the present invention includes providing to areactor a hydrocarbon feedstock preferably with relatively high moisturecontent, such as un-dried wood or Powder River Basin coal, which can berepresented by C_(y)H_(x)O_(z)N_(a)S_(b)Ash_(c).nH₂O, and oxygenobtained from an air separation plant. The feed can also include a fluxto control slag properties and make-up metals to replace incidentalmetal losses. Pyrolysis of the moist feedstock releases fuel-boundhydrogen (H_(x)) as a gas, moisture (nH₂O) as steam and carbon (C_(y))as a solid; other constituents of the feedstock (O_(z), N_(a), S_(b) andash) are also released (i.e., molecular bonds broken) by the pyrolysis.Also, at least a portion of the C_(y) is oxidized to carbon oxides withoxygen derived from molten iron oxide (FeO_(x)), an endothermicreaction, and at least a second portion of the carbon is oxidized tocarbon oxides with oxygen from an air separation plant, an exothermicreaction that at least partially balances the above endothermicreaction. In one embodiment, the molten metal alloy contains tin; andsulfur, if any is contained in the hydrocarbon feedstock, reacts withthe tin to form the volatile species SnS and a small concentration ofH₂S. The ash is also fused and migrates into the slag.

At the same time, a portion of the steam (H₂O) is reduced to H₂ while aportion of the iron is oxidized to FeO_(x). The O₂ that is introducedburns either iron to FeO_(x); H₂ to H₂O; or carbon to mixed carbonoxides to produce additional heat and achieve an energy balance aboutthe reactor.

The molten metal and slag must be contained within a suitable reactor tomaintain the desired reaction conditions. Further, the reactants shouldbe provided in a manner conducive to good mixing and high contactsurface area. High-temperature reactors suitable for establishing goodgas/liquid/solid contact are utilized in the chemical and especiallymetallurgical industries.

The reactor can be maintained at an elevated pressure if necessary foradequate residence time in the reactor. For example, it may be desirableto maintain an elevated pressure, such as at least about 3 atmospheres(44.1 psi). A slightly elevated pressure in the reactor can bebeneficial for minimizing the size overall of the first compressionstage. For example, the pressure in the gasification reactor can beabout 50 psi and up to about 400 psi. Pressure in the gasificationreactor can be achieved, for example, by employing an air separationunit (ASU) that produces liquid (as opposed to gaseous) oxygen.Periodically, however, the gasification reactor must be tapped to removeslag, and tapping under pressure (or releasing pressure before tapping)can be difficult and costly.

One reactor system that can be useful for gasification according to thepresent invention, referred to as a bath smelter, utilizes lances toinject the steam and other reactants into the molten metal. Examples ofreactors utilizing top or side submerged lances to inject reactants aredisclosed in U.S. Pat. No. 3,905,807 by Floyd, U.S. Pat. No. 4,251,271by Floyd, U.S. Pat. No. 5,251,879 by Floyd, U.S. Pat. No. 5,282,881 byBaldock et al., U.S. Pat. No. 5,308,043 by Floyd et al. and U.S. Pat.No. 6,066,771 by Floyd et al. Each of these U.S. patents is incorporatedherein by reference in its entirety. Such reactors are capable ofinjecting reactants (e.g., hydrocarbons and oxygen) into the moltenmetal at extremely high velocities, approaching Mach 1, therebypromoting good mixing of the reactants.

The major function of the top-submerged lance (TSL) bath smelter is tomaximize contact between the solid, liquid and gas phases within thereactor. FIG. 4 schematically illustrates a cross-section of such areactor. The reactor 500 includes sidewalls 502 that are adapted tocontain the molten metal 504 and slag 506. The sidewalls 502 canoptionally be cooled, such as by water cooling. A refractory lining 503is provided to insulate the portion of the reactor containing the moltenmetal 504 and slag layer 506. At least one top-submerged lance 508 isdisposed through the top of the reactor and is adapted to injectreactants such as hydrocarbons and oxygen into the metal 504 or the slag506 at a high velocity. The top-submerged lance 508 terminates andinjects the reactants at or below the surface of the slag layer 506,such as near the interface of the molten metal 504 and the slag layer506.

The moisture is released as steam when the hydrocarbon feedstock to begasified is introduced into the reactor 500 containing the molten metal504 and the slag 506 through a top-submerged lance 508 at a highvelocity. The fuel-bound H₂ in the hydrocarbon feedstock is released asH₂ gas and carbon gasifies by reducing the metal oxide in the slag backto the metal. The oxidation potential within the reactor is controlledat a substantially constant value by introducing a hydrocarbon feedstockto the reactor—the carbon in the feedstock lowers the oxidationpotential of the system thereby continuously driving the metal back intothe melt, whereas the moisture accompanying the feedstock increases theoxidation potential of the system thereby driving the metal back to itsoxide. The result of equal oxidation and reduction rates is that the FeOcontent of the slag remains substantially unchanged. As is discussedabove, the hydrocarbon feedstock can be, for example, coal, petroleumcoke, municipal waste, scrap tires, tar sands, low-grade crude oil, woodor similar low-value feedstocks. The particulate solid feedstock or theliquid hydrocarbon feedstock is injected into the reactor at theslag/alloy interface under conditions of intense mixing such as byinjecting down a submerged lance 508 and/or 510. For example, a singlelance can be used where the lance includes multiple annuli to allow thesimultaneous injection of several reactants. An iron-containinghydrocarbon feedstock such as scrap tires can advantageously supplyadditional iron to the reactor to make up for incidental losses of theiron.

Thus, the hydrocarbon feedstock is subjected to gasification within thereactor 500. That is, the hydrocarbon feedstock is quickly pyrolized torelease fuel-bound H₂, to release moisture as steam and form carbon. Thecarbon gasifies while also acting as a reductant for the metal oxide inthe slag 506. Therefore, as compared to conventional gasification, asubstantial portion of the carbon is oxidized by the metal oxide (FeO)contained in the slag 506.

A heat balance must be achieved around the reactor 500 and little heatis provided by the iron-steam reaction, as it is only mildly exothermic.Since the principal source of H₂O is the moisture carried in with thehydrocarbon feedstock that is injected down a lance, heat must beprovided to convert that liquid or chemically-bound moisture into steamat the reaction temperature; thus additional heat must typically besupplied to the reactor. In this regard, oxygen can also be injectedinto the reactor to burn a portion of the hydrocarbon, metal or the H₂and provide the additional heat. For example, substantially pure O₂ gascan be injected down a second lance 510. The O₂ oxidizes the moltenreactive metal, hydrocarbon or H₂ in an exothermic reaction and createsthe heat necessary to raise the temperature of the incoming moistureassociated with the hydrocarbon feedstock to the reactor operatingtemperature and to sustain the oxidation of the reactive metal by theformed steam. Preferably, a substantially pure oxygen-containing gas isprovided and it is typically advantageous to minimize the amount ofnitrogen (e.g., from air) injected into the reactor. However, it may benecessary to dilute the O₂ gas with a carrier gas to reduce thepossibility of burning the lance 510.

A crude syngas containing CO and H₂ can be removed through an outletport 512. In addition, slag 506 can be periodically tapped (removed)through slag outlet port 514.

As is noted above, the slag composition can include a number ofcompounds, including silica (SiO₂), calcium (CaO), alumina (Al₂O₃) andmagnesia (MgO). It has been advantageously found according to thepresent invention that when other oxides are contained within the slag506, the iron oxide requires a higher reducing potential for producingiron metal. Therefore, an additional amount of carbon from thehydrocarbon feedstock is necessary and the equilibrium gas compositionresulting from the reductive cleaning of the slag advantageously has ahigh CO:CO₂ ratio. This advantageously decreases the amount of CO₂ perunit energy that is produced in accordance with the present invention.For example, a CO:CO₂ ratio of 4, contains 80 percent CO and 20 percentCO₂ (ignoring other gases), whereas a CO:CO₂ ratio of 2 contains 66.7percent CO and 33.3 percent CO₂. Combusting either gas produces the sameamount of CO₂ (100 percent). However, more work is derived from the gaswith the higher CO content. Therefore, the higher the CO:CO₂ ratio, thegreater the amount of work that can be accomplished per unit of CO₂produced. In this regard, it is preferred that the volume ratio ofCO:CO₂ exiting the reactor 500 (e.g., the raw syngas) is at least about3, more preferably is at least about 5 and even more preferably is atleast about 7.

Controlling the oxidation potential of the reactor contents controls therate of the reduction reaction and therefore the amount of iron oxide inthe slag 506 that reduces to iron and reports to the melt 504. This ratecan be maximized by controlling the relative amounts of oxygen gas andcarbon from the hydrocarbon feedstock that are injected into the reactor500. In turn, these relative amounts of oxygen and carbon control thepartial pressure ratio of oxidized gases to total gases, as expressed bythe fraction: $\begin{matrix}{\frac{{H_{2}O} + {CO}_{2}}{H_{2} + {H_{2}O} + {CO} + {CO}_{2}}.} & (10)\end{matrix}$

The preferred value for this ratio can be established throughminimization of Gibbs' free energy for the reduction reaction. That is,the method of the present invention is most effective and produces thehighest CO:CO₂ ratio when the value of the ratio of the oxidizing gasesto total gases is determined by the Gibbs' free energy minimizationtechnique for the particular hydrocarbon feedstock being used. Processcontrol can also be based on approaching (targeting) the pre-calculatedpreferred ratio of oxidized to total gases, which is unique for eachdifferent hydrocarbon feedstock and which value when approached insuresrapid reduction of iron oxide to iron. That is, CO₂ production can bereduced by using the Gibbs' free-energy minimization technique.

A flowsheet illustrating the gasification of a hydrocarbon feedstock andsubsequent treatment of the off-gas according to the present inventionis illustrated in FIG. 5. The gasification process can employ a reactor602 that is preferably a bath smelter similar to that described abovewith respect to FIG. 4. The reactor 602 produces a syngas, which ispassed to a purification train 682 to remove contaminants from thesyngas.

After the syngas purification train 682, valves 670 control thedirection of the syngas stream depending on the desired end products.For example, the syngas stream from reactor 602 can be refined such asby processing through a water gas shift reactor 634 to increase theamount of H₂, and/or a pressure swing adsorption (PSA) unit 636 wherecarbon oxides are separated from H₂. The H₂, if desired, can then befurther compressed for shipment or for storage 650. All or a portion ofthe syngas stream can be taken to an electricity generating turbine 642to burn CO and H₂ and generate electricity. All or a portion of thesyngas can also be sent to hydrocarbon synthesis 690. For hydrocarbonsynthesis, some portion of the syngas will likely require conversion toH₂ by water gas shift 634 followed by a PSA 636 to isolate H₂ fromco-mingled CO₂.

As is described more fully below, the gas purification train 682 canoptionally include multiple units-of-operation for: (a) rapid gascooling by water quenching; (b) gas cooling and heat recovery by heatexchangers; (c) removal of solid pollutants such as fine particles, forexample by filtration; (d) catalytic conversion of carbonyl sulfide(COS) to hydrogen sulfide (H₂S); (e) condensation of water vapor andsimultaneous removal of soluble halogen acid gases such as HCl and HF;(f) amine scrubbers, solvents or absorbents such as metallic iron orzinc to capture hydrogen sulfide (H₂S); and/or (g) other purificationunit operations for capturing pollutants originating within thehydrocarbon feedstock, such as activated carbon for capturing volatilespecies of mercury, a common pollutant emitted by coal-fired electricalgenerating plants. Additional equipment is discussed in more detailbelow with respect to FIG. 6.

By way of illustration, the temperature of the syngas stream can berapidly reduced by water quenching to preclude corrosion issues thatarise from high temperatures and high CO concentrations. After quenchingto a temperature that precludes corrosion issues, heat can be recoveredfrom the syngas stream utilizing conventional heat exchangers and therecovered heat can be used to raise steam. Fine particulates, such asfurnace dust and condensed SnS, can be removed from the syngas stream,and the particulates can be agglomerated and roasted with oxygen. Theroasted product (calcine) can be re-injected into the reactor toconserve metal values and the SO₂ from the roasting operation can bedirected to a Claus plant for recovery of sulfur a salable by-product.

Fine particulates, such as furnace dust, can also be removed from thesyngas stream and after agglomeration and roasting, they can bere-injected into the reactor. Any COS that may be present in the syngasstream can be catalyzed to H₂S and the H₂S can be removed from thesyngas stream by amine scrubbing or other processes. The H₂S releasedfrom the amine regeneration unit operation can be directed to the Clausplant, where it will react with the SO₂ derived from roasting furnacedust to form elemental sulfur:2H₂S+SO₂→3S+H₂O  (11)If insufficient H₂S is available to react with the SO₂, H₂ can beprovided to the Claus plant, as needed to meet the reduction requirementfor making elemental sulfur.

Slag from the reactor 602 can be tapped (removed), preferably in anamount approximating the amount of ash and flux materials that areadded, or in an amount that precludes the rapid build-up inconcentration of some compound in the slag, such as vanadium pentoxide,which is frequently present when petroleum coke is utilized.

According to the present invention, burning relatively low-ash carbonfeedstocks is preferable to burning high-ash carbon feedstocks. This isbecause a flux, usually CaO, SiO₂ or both must be added in proportion tothe amount of ash in the feedstock to control slag properties. Thus, forhigh-ash carbon, there must be a large slag tap so that an equivalentamount of slag is removed as ash and flux are added. The slag typicallycontains about 2% tin and about 30% iron, derived from the oxidation ofmetal alloy, and this can translate into a significant economic loss ifnot recovered and recycled to the reactor.

However, coal and wood are plentiful and widely distributed and can beused as a hydrocarbon feedstock for producing clean gasoline and dieselfuels, or other products, in accordance with one embodiment of thepresent invention. The relatively higher ash content of coal andconsequently high slag and tin losses, however, is problematic.Aggressive coal cleaning such as froth flotation is a widely practicedapproach known for minimizing ash content when using coal. Even withsuch measures, however, there may be more ash than is economicallydesirable.

One aspect of the present invention anticipates recovering the residualtin and iron from the tapped slag. The process comprises mixingelemental sulfur, a plant by-product, into the slag just after tappingand while the slag is still hot. Sulfur will react with either elementaltin (Sn) or tin dioxide (SnO₂), whichever form is present, to create thevolatile tin sulfide, (SnS). If SnO₂ is present, SO₂ also will beformed. Both reactions are exothermic and the heat derived from thereactions can advantageously off-set thermal losses to the environment.

Immediately after tapping, the slag can be directed into a heatedcrucible (or converter). Using lances, sulfur, irrespective of itsstate, can be blown into (through) the hot slag using a gas that isnon-oxidizing with respect to sulfur and contains little or no nitrogen.The off-gas from the heated crucible will contain the volatile species,SnS and SO₂, which can be directed to the dry bottom quench. Any excesssulfur (above the stoichiometric requirement to react with any Sn and/orSnO₂ in the slag) will react with the iron to form iron sulfide.

After recovery of residual tin from the slag, iron may be recovered fromthe FeO_(x) and FeS, if any, by admitting hydrocarbon and oxygen to theconverter. To preclude slag freezing, additional heat may be introducedinto the converter, such as by burning natural gas.

Any SnS entering the quench can be captured in a baghouse and recycledafter oxidation to SnO₂. Any SO₂ entering the quench will react with theH₂ to form H₂S and H₂O. The H₂S can be captured by an amine scrubber andultimately processed back to elemental sulfur in a Claus plant. Thewater can be removed by chilling.

After the “sulfur blow” to recover tin and the addition of hydrocarbonand oxygen to recover the iron, the lances can be removed (retracted)and the slag quenched in a wet-bottom quench. This quickly freezes theslag and controls particle size, minimizing crushing requirements.

One process flow according to the present invention, including thecomponents of a gas purification train can be understood with referenceto FIG. 6, which illustrates the co-generation of H₂ and electricityaccording to the present invention.

As illustrated in FIG. 6, reactor 602 generates a syngas stream from ahydrocarbon feedstock as is described above. Steam for input to thegasification reactor 602 largely is provided by evaporation of moistureassociated with the hydrocarbon feedstock but can be supplemented byadditional steam.

Heat must be supplied to the reactor 602 to raise the temperature of theincoming feedstock to the reaction temperature. According to a preferredembodiment, oxygen (O₂) from an air separation plant 614 is supplied tothe reactor 602 to provide the oxidant for that heat.

In the reactor 602, O₂ can generate heat by: (a) reacting with the metalto form a metal oxide; (b) reacting with hydrogen to form steam; or (c)by reacting with carbon derived from pyrolysis of the hydrocarbon. Bothreactions (a) and (b) above decrease the amount of metal available toreact with steam to form H₂; it therefore it is preferred to provide thereactor with sufficient metal, over and above that required to producethe desired amount of H₂, to react with only sufficient O₂ to providethe necessary heat.

Simultaneously, a hydrocarbon feed is provided to the reactor 602 toreduce the iron oxide contained in the slag back to iron whichre-dissolves into the molten metal. The O₂ that is injected into thereactor 602 also generates heat by supporting the partial oxidation ofthe carbon from the hydrocarbon feedstock to CO in the highly reducingenvironment of the reactor 602. By controlling the carbon-to-oxygenratio, which in turn controls the ratio of oxidizing to total gasespreviously presented, the oxygen present can oxidize the carbonpredominately to CO, while at the same time minimizing the formation ofCO₂. To preclude potential corrosion, a carrier gas (preferably devoidof N₂) may be used to dilute the O₂ prior to injection into the reactor602.

Carbon, steam and H₂ are all released by pyrolysis of the hydrocarbonfeedstock in reactor 602. One portion of the carbon serves as thereductant to render the metal oxides back to the metals andsimultaneously generate CO by gasifying the solid carbon. Anotherportion of the carbon reacts with O₂ which, by controlling the oxygenpartial pressure, expressed as the ratio of the partial pressures of theoxidizing gases to that of the total gas stream (Equation 10), controlsthe rate at which the reactive metal oxide is reduced back to thereactive metal. Advantageously, the highly reduced atmosphere that isrequired to reduce the reactive metal oxide is also high in CO relativeto CO₂ and high in H₂ relative to H₂O. A syngas stream comprised of highCO and H₂, with lesser amounts of CO₂ and trace impurities, results.

A preferred hydrocarbon feedstock is a moisture-containing low-ashhydrocarbon-bearing material high in its percentage of both carbon andhydrogen, and low in its percentage of oxygen and ash. Low ash reducesslag losses, and low oxygen enhances the available (fuel bound)hydrogen. That is, fuels with higher oxygen content such as municipalwaste will consume some of the available H₂. In this instance, thehydrogen released as elemental hydrogen will be the total hydrogen minusabout ⅛ of the oxygen. High carbon and hydrogen values minimize thetotal amount of fuel required while simultaneously producing a desirablesyngas stream.

The moisture-containing hydrocarbon feedstock can also be injected intothe reactor 602 using a top-submerged lance or similar device. When soinjected, the particulate feedstock can be entrained in a gas such as COor CO₂, and during steady-state operation a portion of the purified andcompressed syngas stream can advantageously be recycled and used as acarrier gas. It is also possible, although less desirable, to add themoist hydrocarbon feedstock to the reactor 602 by other means, such asby simply dropping the feedstock into the reactor 602.

Other materials such as fluxes can be injected into the reactor 602, forexample to control the properties of the slag such as slag fluidity ortendency to foam. The ash-forming minerals that can be part of thehydrocarbon feedstock contribute to the slag layer within the reactor602. When coal is used as a hydrocarbon feedstock and there is adequatecalcium oxide (CaO) in the slag (either inherent in the feedstock oradded as flux), the slag can be tapped from the reactor 602 and sold asa pozzolanic by-product. Additionally, other materials such as tincompounds, cassiterite ore or other materials such as iron compounds orore may be added to make-up for losses of metal values. According to aparticularly preferred embodiment, tin is a diluent metal andcassiterite ore (SnO₂) is injected into the reactor to make-up for tinlosses.

Thus, in the gasification reactor 602, CO derives from two reactions:(1) the gasification of carbon with FeO (endothermic); and (2) thepartial oxidation of carbon (exothermic) to CO. Employing an IGCC 652,this CO can be advantageously used to generate electricity. Theadvantage is two-fold: (1) the CO to CO₂ conversion (the second oxygenatom accepted by the carbon) embodies approximately two-thirds of theenergy available from the complete oxidization of carbon; and (2) gasfired turbines, especially when operated as an IGCC 652, comprise ameans of generating electricity that is about 66 percent more efficientin converting thermal energy to electric energy than the conventionalcoal-fired, steam-driven-turbines that currently generate approximately51 percent of the electrical needs of the United States. As analternative to generating electricity, additional H₂ may be produced byutilizing the approach of conventional gasification, which is the watergas shift reaction 634 followed by isolation of the formed H₂ and CO₂,usually with a PSA unit 636.

The amount of O₂ introduced into reactor 602 is preferably justsufficient to support combustion of enough carbon, hydrogen or iron tosupply the heat required for the endothermic conversion of metal oxideto metal. The O₂ may have to be introduced as a mixture with a carriergas to preclude inadvertent oxidation of the injecting lance. Off-gasfrom the gasification reactor 602 is advantageously in a reduced state.

A crude syngas stream is removed from gasification reactor 602. Thiscrude syngas stream can include H₂, un-reacted steam, CO, CO₂, H₂S, COS,furnace dust, and gaseous tin sulfide (SnS).

The syngas stream also carries substantial heat value. The hot syngasstream can be passed through a quench 608 where liquid water rapidlycools the syngas stream but without substantial loss of recoverableheat. Preferably, the quench 608 is a dry bottom quench wherein acontrolled amount of liquid water rapidly cools the syngas stream to areduced temperature, such as about 900° C. or lower. The rapid coolingis designed to minimize the Boudouard reaction that is favored above700° C. and which consumes carbon (from the steel of the equipmentwalls) by reacting with CO₂ to form CO. However, the farther thetemperature is dropped below about 700° C., the less heat that isavailable downstream for producing additional electricity. Thus, it ispreferred to reduce the syngas stream to a temperature in the range offrom about 900° C. to about 700° C.

The use of such a quench 608 to cool the syngas stream canadvantageously:

-   -   1. Reduce metal “dusting”, i.e., the destruction of the        containing ductwork, by rapidly dropping the temperature through        the temperature range where the “dusting” reaction occurs        (thought to be caused by the Boudouard reaction, wherein carbon        contained in the steel plus CO₂ yields CO);    -   2. Minimize the potential for the inadvertent deposition of        carbon from the reverse Boudouard reaction;    -   3. Shift some CO to H₂ by the water gas shift reaction thereby        increasing the amount of H₂. It is believed that this conversion        may advantageously be catalyzed by nascent iron oxide dust that        can be simultaneously expelled with the reactor gases;    -   4. Cool the hot gases to more manageable temperatures and        volumes without substantial loss of heat; and    -   5. Condense any gaseous SnS to solid SnS.

The syngas stream can then be passed through waste heat exchanger 610 tofurther cool the syngas stream and to provide heat for additional steam,thereby conserving heat value. For example, the temperature of the gasstream can be dropped to about 250° C. and the recovered heat used togenerate steam.

The syngas stream can also include some contaminants. These can includeCO and H₂S, both arising from carbon and sulfur dissolved in the metalreacting with the steam, and entrained particulates of frozen slag,metal oxides (e.g., iron oxide) or carbon which are ejected from themolten metal bath and slag. The syngas stream can also include SnS whichvolatilizes from the molten metal bath and is condensed in the quench608. The particulate contaminants can be removed from the syngas stream,such as by a filter 616. Alternatively, other means such aselectrostatic precipitators or bag houses can be used to separateparticulates.

Preferably, the SnS is conveyed to a dryer and pelletizer 628 with theother particulates for agglomeration and the pellets are then treated ina roaster such as a fluidized bed roasting unit 626 to convert the SnSto SnO₂ and SO₂ through the introduction of O₂ from the air separationunit 614. The SnS is preferably roasted in the roasting unit 626 in amanner that the O₂ remaining in the roasting gas is minimized, so thatlittle or no O₂ is mixed with the gaseous SO₂ coming off the roastingunit 626.

The SO₂ can then be transferred to a Claus plant 632 where it iscombined with H₂S from an amine regenerator 630 or, if sufficient H₂S isnot available for the Claus reaction, H₂ exiting the PSA unit 636 can beused as the reductant. The Claus plant 632 produces sulfur which is asalable by-product of the process. The SnO₂ can advantageously berecycled to the reactor 602 to reduce tin losses from the system.

After removal of particulate contaminants, if any, the syngas stream canbe treated in a catalytic reactor 618 to convert carbonyl sulfide (COS)in the syngas stream to H₂S. This reaction is typically carried out at atemperature of about 200° C. with a catalyst. Other means to remove COS,such as physical solvents, can be used. Thereafter, the syngas streamcan be cooled in a chiller 620 to condense excess steam and the watercan be recovered and recycled to water header 640. The chiller 620 canalso advantageously remove soluble chlorine compounds. Chlorine is acommon contaminant in many of the types of hydrocarbon feedstock forthis process. The chlorine, released during pyrolysis, can react withthe hydrogen to form gaseous HCl. The resulting syngas stream isrelatively pure, except for trace amounts of H₂S.

Considerable heat is released as steam is condensed from the syngasstream by the chiller 620 and this heat can be captured within a hotwater header 640 for recycling within the steam system. The Cl⁻ ionconcentration in the condensed water is preferably controlled topreclude corrosion problems and assure continued adsorption of theextremely water soluble HCl gas.

The syngas stream can be passed through a compressor 624 to increase thepressure of the syngas stream, preferably to at least about 200 psi,more preferably at least about 400 psi. It then can then be passedthrough an amine scrubber 622 to remove H₂S. The H₂S-rich amine solutionfrom the scrubber can be passed to an amine regenerator 630 toregenerate the amine solution which is then passed back to the aminescrubber 622. Other means for removing the H₂S, such as physicalsolvents (e.g., methanol), can also be used.

The H₂S can then be combined with SO₂ in a Claus plant 632 for theproduction of elemental sulfur. It may also be desirable to divert aportion of the H₂ to the Claus plant 632 since there may not be enoughH₂S available to stoichiometrically match the SO₂ from the roaster 626.The tail gas from the Claus plant 632 may be directed to a quenchdownstream from the reduction reactor for final gas clean-up (not shownin FIG. 6).

As is noted above, one aspect of the present invention is directed tothe recovery of residual tin from the tapped slag. The process comprisesmixing elemental sulfur, a process by-product from the Claus reactor632, into the slag just after tapping and while the slag is still hot.Sulfur will react with either elemental tin (Sn) or tin dioxide (SnO₂),whichever form is present, to create volatile tin sulfide (SnS). If SnO₂is present in the slag, SO₂ also will be formed. Both reactions areexothermic and the heat derived from the reactions can advantageouslyoff-set thermal losses to the environment.

More specifically, immediately after tapping, the slag can be directedinto a heated crucible or converter. Using lances, sulfur, irrespectiveof its state, can be blown into through the hot slag using a recycle gasthat is non-oxidizing with respect to sulfur and contains little or nonitrogen, including process recycle gas. The off-gas will contain thevolatile species SnS and SO₂ which can be directed to the dry bottomquench 608. Any SnS entering the quench can be captured in a baghouseand recycled after oxidation to SnO₂. Any SO₂ entering the quench willreact with the H₂ to form H₂S and H₂O. The H₂S can be captured by theamine scrubber 622 and ultimately processed back to elemental sulfur inthe Claus plant 632. The steam can be removed by chiller 620.

Any excess gaseous sulfur, over and above that required to react withtin species, will react with the iron to form iron sulfide. After tinrecovery, iron, whether present as FeO or FeS will be recovered byintroducing a hydrocarbon and oxygen into the converter.

After the “sulfur blow” and iron reduction, the lances can be removed(retracted) and the slag quenched in a wet-bottom quench. This quicklyfreezes the slag and controls particle size, minimizing crushingrequirements.

After removal of H₂S in the amine scrubber 622, the syngas stream canoptionally be conveyed to PSA unit 636 to separate carbon oxides fromH₂.

The gasification method of the present invention can advantageouslyincrease the amount of CO and/or H₂ that is produced in the syngasrelative to the amount of CO₂ simultaneously produced. Table 2illustrates a comparison of the product syngas from the gasification ofan identical quantity of an identical hydrocarbon feedstock for themethod of the present invention and the E-Gas process (Conoco-Phillips),an oxygen-blown coal gasification process that is currently regarded asan environmentally friendly commercial gasification process. The datapresented in Table 2 represent content of the raw gas stream afterremoval of contaminants but before any unit operations to adjust the gasratios, such as PSA or water gas shift. TABLE 2 E-Gas CompositionPresent Invention Syngas Component (kmol/cycle) (kmol/cycle) H₂ 22 24 CO27 35 H₂O 25 10 CO₂ 13 5

As is illustrated by Table 2, the method of the present inventionproduces a higher concentration of CO and H₂ relative to CO₂. The CO:CO₂ratio for the method of the present invention is about 7, whereas forthe E-gas process it is about 2.

In the embodiment illustrated in FIG. 6, the syngas can be burned in anIGCC 652 to produce electricity. Some of this electricity can be used tooperate different unit operations, such as air separation plant 614 andthe various compressors. Excess electricity can be sold into the powergrid.

As is illustrated in FIG. 7, the IGCC 652 includes several unitoperations. These unit operations include a gas-fired turbine 642 towhich air (or oxygen) is fed along with previously compressed syngas toproduce electricity via generator 644. The output heat of the gas-firedturbine 642 is utilized to generate steam in a heat exchanger 648, whichsteam can be input to a steam-turbine generator 646 to generateadditional electricity. Any excess steam created in heat-generatingunits, for example, heat exchanger and superheater 610, chiller 620,Claus plant 632 and fluid bed roaster 626 also can be directed to thesteam-turbine 646 to produce additional electricity.

One aspect of the present invention is directed to the production ofammonia using the manufactured low-cost, high-purity hydrogen gas andnitrogen gas from the air separation plant 614 as reactants. One of theimportant aspects of the method according to the present invention isthe in-situ manufacture of large quantities of H₂ at a relatively lowcost. It is believed that one of the primary hindrances to the methodsdisclosed in the prior art for the production of ammonia is the need forhigh volumes of H₂ gas and the high cost associated with the H₂ gas.According to the present invention, high volumes of hydrogen gas can beeconomically generated in-situ.

The nitrogen and hydrogen are combined in a H₂:N₂ molar ratio of about3:1 in order to maximize the production of ammonia (NH₃). In a typicalammonia production method, a gas including hydrogen and nitrogen iscompressed to about 200 atmospheres of pressure and passed over an ironcatalyst at a temperature of from about 380° C. to about 450° C.

The methods of the present invention can provide numerous advantages ascompared to prior art methods. Among these are:

-   -   reduced CO₂ (a greenhouse gas) is produced per unit H₂ or energy        produced as compared to conventional gasification. CO₂ emissions        per unit of H₂ produced are: conventional gasification about 22        tons CO₂ per ton H₂; the method of the present invention about        14 tons CO₂ per ton H₂. Steam methane reformation (SMR) emits 13        tons CO₂ per ton H₂, however, SMR is not desirable due to the        high cost of its feedstock, natural gas.    -   low-value hydrocarbon fuels, inducing high-sulfur hydrocarbons        or hydrocarbons containing chlorine, can be utilized.    -   the syngas from the gasification reactor is kept in a highly        reducing state.        Removal and Preclusion of Pollutants

In accordance with the foregoing method, a gas purification train can beused for (1) recovering heat; (2) removing pollutants; and (3)precluding the formation of pollutants from components comprising thesyngas stream. Pollutants contained in the feed material whichdistribute to the gas phase (as opposed to the alloy or slag phase)determine what unit operations are required for removing the pollutants.

By way of example, listed below is a sequence of unit operations (withreference to FIG. 6) designed to remove pollutants that might beexpected when utilizing coal as the carbon source for the process of thepresent invention. Pollutants removed can include fine solidparticulates such as furnace dust and SnS, water, chlorine, sulfur andmercury. Pollutants whose formation is advantageously precluded includenitrogen oxides (NO_(x)) and furans and dioxins.

-   -   1. Dry bottom quench 608: this unit is designed to rapidly        decrease the gas temperature from 1300° C. to 700° C. by        injecting liquid water. The purpose of the quench is to preclude        a potential metallurgical problem known as dusting, which is the        deterioration of the metal that contains the gas and is known to        occur at temperatures above about 700° C. in syngas streams with        a high concentration of CO.    -   2. Heat exchanger and steam super heater 610: This unit        operation is a conventional heat exchanger and super heater        designed to recover the sensible heat of the gases.    -   3. Metal filter 616: After the gas is cooled, particulates are        removed by a candle filter employing a metal filter medium. The        fine solids that are recovered are comprised of furnace dust and        tin sulfide.    -   4. Fluid bed roaster 626: In a unit external to the purification        train, the particulates collected from metal filter 616 are        roasted in a fluid bed roaster in oxygen to form SO₂ and SnO₂.        The SnO₂ is returned to the furnace with the dust. The SO₂        advances to a Claus plant 632, where the SO₂ is combined with        H₂S, recovered from the amine regeneration system or H₂ from the        product line to form elemental sulfur.    -   5. COS to H₂S 618: In this unit operation, a catalyst is used to        hydrolyze the carbonyl sulfide to hydrogen sulfide and carbon        dioxide, and is part of the sulfur removal system. Sulfur is a        ubiquitous contaminant of coal and other hydrocarbons.    -   6. Chiller 620: The chiller is designed to remove steam        originating from two sources: (i) steam that was not converted        to hydrogen in the gasification reactor; and (ii) water,        converted to steam, added to the dry bottom quench. Acid gases        such as HCl or HF also will be removed by the chiller due to        their high solubility in water. Their removal is related to        precluding formation of furans and dioxins.    -   7. Amine scrubber 622: This standard unit operation is part of        the system for removing sulfur, and it operates in conjunction        with the amine regeneration unit 630.    -   8. Activated carbon adsorber (not illustrated): Mercury can be        adsorbed by activated charcoal. Mercury can be recovered from        the loaded carbon and the charcoal reactivated and reused.    -   9. Pressure swing adsorption (PSA) system 636: This system is a        standard means for disengaging commingled gases and typically is        used to separate H₂ from CO and CO₂ to yield a pure salable        stream of H₂.

Dioxins are a family of compounds known as polychlorinateddibenzo-dioxins (PCDD), and furans are a family of compounds known aspolychlorinated dibenzofurans (PCDF). There are about 210 compounds inthese two families, and they have a wide range of environmental,chemical and physical properties. Two methods are postulated for theirformation. Both methods are believed to require the presence of all ofthe following precursor conditions: (1) the presence of solid particlescontaining carbon structures; (2) the presence of organic or inorganicchlorine; (3) the presence of iron, copper, manganese or zinc ions; (4)an oxidizing atmosphere; and (5) a temperature window of 250° C. to 400°C.

According to the present invention, the formation of dioxins and furanscan be substantially precluded because oxygen is absent as the hotsyngas stream is cooled through the temperature window of 400° C. to250° C., and chlorine (Cl) and fluorine (F) are removed before the gasesare reheated through that temperature window.

The formation of nitrogen oxides can also be precluded or reduced byreducing the oxidation temperature inside the gas fired turbine. Wateror other oxidized gases such as CO₂ can be used as a temperature controlmethod.

There are numerous methods for removing elements that are consideredpollutants from the syngas stream. In terms of what potential pollutantsto remove, the starting point is an analysis of the solid hydrocarbonfeed being used and all other materials that enter the process. Themethod of the present invention advantageously partitions all elementsadmitted to the process to one of four locations—the slag, the alloy,the reactor dust which includes tin sulfide or the syngas stream.

Slag

Refractory oxides such as SiO₂, Al₂O₃, CaO and MgO report to the slag.Control of slag properties depends upon taking a sufficiently large slagtap to preclude the build-up of potentially detrimental elements. Forexample, the ash from petroleum coke typically has a high percentage ofvanadium, which is expected to report to the slag as vanadium oxide. Thevanadium content of the slag can be kept within pre-established limits,preferably less than 20 percent for satisfactory slag properties, byadjusting the amount of flux added and correspondingly, the amount ofslag tapped.

Alloy

Some elements that may be associated with the solid hydrocarbon feed,such as oxides of nickel or copper, are expected to be reduced by thecarbon and report to the alloy. These elements dilute the alloy but donot render it ineffective. After some time, elements (other than tin andiron) accumulate in the alloy, and the entire alloy may have to bechanged out. Value received from the “contaminated” alloy can exceed thecost of a fresh alloy system.

Reactor Dust

This material, extracted from the syngas stream by filtration, isagglomerated and then roasted to produce dry SO₂, for sulfur productionby the Clauss process, and calcine, for returning iron and tin oxides tothe reactor that ejected the dust.

Syngas Streams

Solid hydrocarbons derive from living materials and they are comprisedprincipally of carbon, hydrogen, nitrogen, oxygen, sulfur, chlorine andash. Ash may be inherent, comprised of inorganic elements commonlyassociated with the living material, or the ash may be adventitious,washed in from another source. Most ash components are expected topartition to the slag with a few partitioning to the alloy.

The only solid hydrocarbon currently available in North America insufficient quantity to off-set the use of imported oil is coal. Biomassalso could be available in sufficient quantity, but at present there isno biomass collection system in place. Coal (or biomass) can beaugmented with pet coke, municipal waste, and rubber tires, either toenhance the quality of the hydrocarbon or to consume waste therebyreducing or eliminating landfills and their associated ills. The majorpotential contaminants arising from these hydrocarbons are consideredbelow.

From solid hydrocarbon, water and air, the method of the presentinvention creates both a syngas stream that is highly reducing (lowpartial pressure of oxygen), hot, dusty and contaminated with chlorine,sulfur compounds and various other elements.

Precluding Corrosion. A high concentration of CO at high temperaturescan cause corrosion or “dusting” of the metal ductwork containing thegas. For this reason the 1300° C. high CO syngas from the furnace israpidly cooled by injecting sufficient liquid water to reduce thetemperature to 700° C.

Conserving Heat. This is critical for maintaining good efficiency.Standard heat exchangers are used for this purpose.

Particulate Removal. Devices effective in removing particulates from asyngas stream can include: ESPs (electro-static precipitators), metalfilters and (cloth) bag-houses. Metal filters are generally preferredbecause they can withstand the (relatively high) gas temperature. Twotypes of (intermingled) particulates are removed; furnace dust and tinsulfide. Tin sulfide along with associated furnace dust is subsequentlyroasted to recover the tin as tin dioxide, which, along with the furnacedust, recycles to the reactor, and sulfur dioxide which reports to theClaus plant.

Acid Gas Removal. Acid gases include CO₂ (as H₂CO₃); hydrogen sulfide(H₂S), hydrogen chloride (HCl), and hydrogen fluoride (HF). Variousmethods for their removal include:

CO₂. Scrubbing with a solvent, such as the RECTISOL process (Lurgi,Frankfurt, Germany), which removes the CO₂ from the syngas stream, to besubsequently released (upon regeneration of the solvent) and becompressed-and-sequestered. The RECTISOL process uses cold methanol as aphysical solvent and the CO₂ (as well as H₂S, COS and other sulfurcompounds) are removed from the syngas stream. Alternatively, the syngasstream can be burned in pure oxygen yielding a more-or-less pure CO₂,again for compression-sequestration. Other methods for removing CO₂exist, including adsorption on activated carbon.

Sulfur. Carbonyl sulfide (COS) is not removed by conventional amines.For this reason it typically is first hydrolyzed into H₂S;(COS+H₂O→H₂S+CO₂). This reaction proceeds well in the presence of acatalyst.

Some solvents can remove both H₂S and COS. An example is SELEXOL (UnionCarbide), a physical solvent made of a dimethyl ether of polyethyleneglycol.

Halogen Acids. Halogen acids such as HCl and HF are removed in themethod of the present invention due to their extreme solubility inwater. In the chiller, a large amount of steam (added as water at thequench) is condensed. Formation of the cloud of condensed water willdissolve and remove the halogen acids from the syngas stream (and alsosome H₂S). If halogen acids are not removed before amine scrubbing, theywill react (destructively) with the amine.

NO_(x) The formation of appreciable amounts of NO_(x) can be precludedduring combustion of the gas in the gas turbine by the addition ofsufficient water to control flame temperature to below the temperaturethat is required for its formation.

Mercury. Mercury (Hg) is not present in the pet coke. Mercury, however,does exist in coal. Commercial methods for its removal have beendeveloped employing (powdered or granular) activated charcoal foradsorption with regeneration of the activated charcoal achieved by theapplication of mild heat to the sorbent. Such methods can be employedwhen mercury is present in the hydrocarbon feed.

Dioxins and Furans. These toxic compounds (collectively about 210 ofthem) do not exist in the feed; rather, they can form during cooling orheating of the syngas stream as it passes through the temperatureswindow of 250° C. to 400° C., when all four of the following arepresent—oxygen, a carbon structure, chlorine and iron (as a catalyst).Absence of any one of these components will preclude formation.

The method of the present invention is advantageously arranged so thatO₂ is absent as the temperature drops from 400° C. to 250° C. andchlorine is absent as the temperature is raised from 250° C. to 400° C.in the IGCC circuit. The ability to preclude furan and dioxin formationis critical if municipal waste or coal with high chloride content,Illinois coal for example, is used as a feedstock. Municipal waste canbe especially high in chlorine content (from PVC, household bleach andother sources).

In summary, there is often more than one means of removing a pollutantfrom a reducing syngas stream; however, once selected, integration intothe gas purification train is required.

In one embodiment of the present invention, CO₂ can be removed from theatmosphere and sequestered. This embodiment can potentially createrevenue in the form of CO₂ credits that are available in severalindustrialized nations.

According to the present invention, biomass (that otherwise woulddecompose by oxidation in a landfill) can be converted to syngas and thesyngas is converted to methane which in turn is converted to H₂ andsolid, elemental carbon. The hydrogen is available for furtherprocessing, and the carbon is sequestered. Every ton of carbonsequestered is equivalent to excluding 3.7 tons of CO₂ from entering theatmosphere. Since oxidizing biomass does not create CO₂ emissions(oxidizing biomass simply returns CO₂ to the atmosphere that was firstremoved to create the biomass), sequestering carbon derived from biomassessentially removes CO₂ from the atmosphere. Hydrogen thus is producedat no CO₂ cost to the environment.

In yet another embodiment of the present invention, applicable tohydrocarbon feedstocks with low to medium sulfur contents (pet cokeusually is high in sulfur content), the H₂S and COS that appear in thegas stream can be reacted with iron (iron contained in an “iron box”)which can be subsequently roasted along with the SnS recovered by thefilter, pelletized and dried. In this case, roasting converts all sulfurin the feedstock into dry SO₂. Dry SO₂ is especially well suited for themanufacture of sulfuric acid, and is a widely used item of commerce. Theiron introduced into the reactor (along with re-cycled tin) comprisesmake-up iron.

While various embodiments of the present invention have been describedin detail, it is apparent that modifications and adaptations of thoseembodiments will occur to those skilled in the art. However, it is to beexpressly understood that such modifications and adaptations are withinthe spirit and scope of the present invention.

1. A method for the gasification of a hydrocarbon feedstock to form asyngas, comprising the steps of: (a) injecting a hydrocarbon feedstockcomprising at least about 10 wt. % H₂O into a molten metal reactor, thereactor containing a molten metal phase comprising a reactive metal anda slag phase, wherein a portion of the H₂O from the feedstock reactswith the reactive metal to reduce the portion of the H₂O to H₂ and forma reactive metal oxide, and wherein a first portion of carbon from thehydrocarbon feedstock reduces reactive metal oxide contained in the slagphase to the molten metal phase; (b) during the injection of hydrocarbonfeedstock, injecting oxygen into said molten metal reactor to oxidize atleast a second portion of carbon from said hydrocarbon feedstock tocarbon oxides; and (c) recovering a syngas comprising H₂ and CO from thereactor, where the recovered syngas comprises not greater than about 15vol. % CO₂.
 2. A method as recited in claim 1, wherein the recoveredsyngas comprises not greater than about 10 vol. % CO₂.
 3. A method asrecited in claim 1, wherein the recovered syngas comprises not greaterthan about 5 vol. % CO₂.
 4. A method as recited in claim 1, wherein thehydrocarbon feedstock is selected from the group consisting of pet coke,coal, municipal waste, rubber tires, wood and biomass.
 5. A method asrecited in claim 1, wherein the hydrocarbon feedstock comprises at leastabout 25 wt. % H₂O.
 6. A method as recited in claim 1, furthercomprising the step of injecting a second hydrocarbon feedstock intosaid reactor, where the second hydrocarbon feedstock comprises less H₂Othan said first hydrocarbon feedstock.
 7. A method as recited in claim1, wherein the partial pressure ratio of oxidizing gases to total gasesin the reactor as expressed by the fraction:$\frac{\left( {{H_{2}O} + {CO}_{2}} \right)}{\left( {H_{2} + {H_{2}O} + {CO} + {CO}_{2}} \right)}$is determined for the hydrocarbon feedstock by minimizing Gibbs' freeenergy for the reduction reaction employing the hydrocarbon feedstock,and wherein the input rate of a reactant selected from oxygen andhydrocarbon feedstock to the reactor is adjusted to minimize the Gibbs'free energy.
 8. A method as recited in claim 1, wherein the hydrocarbonfeedstock further comprises sulfur-bearing or chlorine-bearingcompounds.
 9. A method as recited in claim 8, further comprising thesteps of: (i) recovering sulfur-containing compounds from said syngas;(ii) oxidizing said sulfur-containing compounds to form SO₂; (iii)contacting said SO₂ with H₂S or H₂; and (iv) extracting elemental sulfurfrom said contacting step.
 10. A method as recited in claim 8, furthercomprising the steps of: (i) removing chlorine-containing compounds fromsaid syngas by dissolving the chlorine-containing compounds in water;and (ii) removing said chlorine-containing compounds by waterpurification.
 11. A method as recited in claim 1, wherein said reactivemetal comprise iron.
 12. A method as recited in claim 11, wherein therate of injection of the hydrocarbon feedstock is maintained such thatthe iron oxide content in the slag phase does not deviate during theprocess by more than about 5 weight percent.
 13. A method as recited inclaim 11, wherein the rate of injection of the hydrocarbon feedstock ismaintained such that the iron oxide content in the slag phase is atleast about 30 wt. % and is not greater than about 65 wt. %.